The loan will finance smart power grid development and expansion, facilitating the integration of renewable energy sources and new connections of clean tech assets, such as heat pumps and EVs.

The project will also boost industrialisation, economic growth and job creation in Spain, safeguarding 10,000 jobs a year in 12 autonomous communities during the implementation period. Additionally, more than 65% of the total investment will go to Spanish regions where per-capita income is below the EU average.

Of the loan, an initial €500 million ($542.7 million) tranche was signed in Madrid by EIB director general for European Union operations, Jean-Christophe Laloux, and Iberdrola finance, control and corporate development director José Sainz Armada.

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“Supporting power grid modernisation to facilitate the integration of new sources of renewable energy is among the priorities included in the EIB Climate Bank Roadmap,” said Laloux in a release.

“This new financing agreement signed with Iberdrola will accelerate Spain’s energy transition, ensure access to sustainable energy for all and contribute to the European Union’s strategic and energy independence.”

Added Armada: “This loan will enable us to speed up the decarbonisation of industry, a key process for Spanish companies.

“We will use this new EIB financing to expand smart grid development in Spain, as this is vital for facilitating the energy transition, boosting efficiency and improving the distribution network and supply quality. We will also contribute to the electrification of the economy and reducing the country’s energy dependence.”

The total investment under the smart grid project amounts to €1.44 billion ($1.6 billion), with the remaining €740 million ($803.2 million) provided by Iberdrola.

Iberdrola operates one of the largest electricity distribution systems in the world with over 1.3 million kilometres of power lines and more than 4,500 substations in Spain, the US, UK and Brazil, supplying electricity to over 35 million globally.

At the end of 2023, the company had green or sustainability-linked financing of more than €54.5 billion ($59.1 billion), including over €20.2 billion ($21.9 billion) of green bonds.

The programme would allow PG&E to accelerate work on its electric system to further improve safety, reliability, capacity and infrastructure health, and to enable new interconnections to clean-energy projects that support decarbonization. Citizens has committed to contributing a large share of its profits from the programme to clean energy programmes in low-income and disadvantaged communities across PG&E’s service area.

If Citizens invests the full $1 billion, it expects the programme to generate hundreds of millions of dollars in charitable benefits over the lives of the leases. The programme is designed so that customers would pay no more for the applicable transmission assets than they would without the programme.

“At PG&E, we have a responsibility to build a better future for everyone whose lives we touch,” said PG&E Corporation CEO Patti Poppe. “We’re committed to finding innovative and affordable new ways to ensure that the transformation of California’s energy system benefits all the state’s residents. We’re excited and honored to partner with Citizens to help some of our most vulnerable communities build resilience against climate change.”

Citizens President Joseph P. Kennedy III said the programme will serve the nonprofit’s mission to support projects and programmes that increase grid strength and decrease electricity costs.

“Our vision is a safe, reliable and clean energy system that leaves no one behind,” Kennedy said. “This partnership with PG&E will advance our march toward a just and equitable clean-energy transition. We look forward to working closely with local communities in need across PG&E’s service area to hear their ideas about the investments that would most benefit them.”

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Programme details

Through the programme, PG&E may offer Citizens options to lease entitlements to PG&E electric transmission assets. PG&E may offer five separate leases of 30 years each, for a total investment of up to $1 billion.

Citizens would make an upfront payment to PG&E as prepaid rent.

Citizens would lease the rights through a wholly owned subsidiary that would be a CAISO participating transmission owner. Citizens would recover the costs of its investments through the CAISO high-voltage Transmission Access Charge, after Federal Energy Regulatory Commission (FERC) review and approval to ensure the costs are just and reasonable.

Citizens has committed to contributing 50% to start, increasing to 90%, of net after-tax profits from its investments in the programme.

Based on the terms of the programme, the transmission assets would remain under PG&E ownership and under the operational control of the California Independent System Operator (CAISO). PG&E would remain responsible for the development, design, permitting, engineering, procurement, construction and operations and maintenance of the relevant assets.

The programme needs the approval of the CPUC and FERC.  

Citizens investments

Pending regulatory approval, PG&E and Citizens expect to close on the first lease option in early 2025, with up to four more to follow through 2030.

Citizens will cap the capital cost component of its FERC rate at an estimate of the rate PG&E could have charged customers without the programme. Due to the size and structure of the programme, Citizens has also agreed to forgo recovery from CAISO customers of its own development and administrative and general costs, among other costs.

The CPUC and FERC have approved two similar programmes between Citizens and San Diego Gas & Electric (SDG&E) — the 117-mile (188.3km) Sunrise PowerLink transmission line, which connects SDG&E’s grid to renewable energy generated in the Imperial Valley; and the Sycamore-Penasquitos transmission line, which links two substations in San Diego via partially undergrounded lines.

A third project — an 18-mile (29km) upgrade to an Imperial Irrigation District transmission line that imports and exports power between California’s Imperial Valley and Arizona — is expected to be in service in spring 2024 and is expected to result in $18 million in charitable funds on a $40 million Citizens investment.

Citizens’ funds from those programmes supported the development of a 39-MW community solar programme to benefit 12,000 low-income customers of the Imperial Irrigation District.

Originally published on Power Grid.

Whenever I think back to 2023, one major sentiment that comes to mind is the urgent need for investment in Europe’s power grid system.

Interconnected renewables are coming online at a pace that the current grid infrastructure wasn’t built to withstand. And although the ramifications of this have started to show, investments seem to be able to bring relief.

Over the last week, this notion has been reinforced as some of Europe’s top utilities have released their financial results for the 2023 fiscal year.

The key takeaway, you ask?

Europe is finally investing heavily into its grid infrastructure with “record levels of investment” a phrase placed on repeat. The adage is sometimes followed either optimistically with “record investment plans” or more somberly with “it’s not enough.”

So, what does this tell us about the investment landscape within which grid business stands?

‘Plans’ are translating into action

Over the last week, utilities have released their financial results and laid out their investment plans for the coming years.

Germany’s 50Hertz is looking to invest €20.7 billion ($22.6 billion) in overhead power lines, on- and offshore cables, substations and other technologies, a three-quarter leapfrog compared to €4.8 billion ($5.2 billion) from the past half-decade.

E.ON is planning a €9 billion ($9.8 billion) increase to its 2024 to 2028 investment plan from €33 billion ($36 billion) to €42 billion ($46 billion), focusing on energy networks and energy infrastructure solutions.

And TenneT, which operates both in Germany and the Netherlands, is expecting to grow its investments to at least €10 billion annually.

Although very much welcomed, one tends to look towards ‘plans’ with a drizzle of scepticism. But what has been surprising is that these utilities and others are simultaneously announcing record investments in their 2023 results.

In Germany, E.ON invested €5.2 billion ($5.7 billion) in network expansion, modernisation, and digitalisation and 50Hertz invested €1.7 billion ($1.9 billion) in grid infrastructure.

TenneT invested €7.7 billion ($8.4 billion) between Germany and the Netherlands.

In the Netherlands, utilities Alliander, Stedin and Enexis each stated record levels of €1.4 billion ($1.6 billion), €1.214 billion ($1.327 billion) and €832 million ($909 million) respectively.

Penning an action plan and moving from paper to implementation are two very different challenges. It is encouraging to see this transition being made.

However, these statistics then beget a follow-up question:

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Is it enough?

In the Netherlands, it is not.

Alliander states that despite their record investments and upward plan, bottlenecks will be recurring on the power grid for at least the next decade. Even though this has been a repeated news item in recent years, it still warrants worry.

A case study to illustrate this is that of Dutch-owned TenneT, which has been mulling sale of its German operations to Germany’s Federal government for months now.

According to Handelsblatt reportage, the Federal Ministry of Economics is very interested in the German TenneT subsidiary, as the company is responsible for important north-south electricity highways.

The Netherlands, on the other hand, want to sell because they are afraid of the billions of euros in investments that will be needed over the coming decade to make the power grid fit for purpose.

Additionally, although TenneT reported healthy financial results for 2023, underlying revenues decreased for the utility by €600 million ($655 million), driven by a decline in ancillary service costs.

Said costs originate in lower market prices for costs incurred by TenneT to compensate for grid losses, maintain energy balance in the grid and pay for alternative electricity routes in case of congested or unavailable grid sections, as is the frequent case in the Netherlands.

Grid congestion and outstanding customer connection requests in the Netherlands, states TenneT, are being addressed through the National Grid Congestion Action Plan (LAN) and “unorthodox measures”, such as flexibility mechanisms, with which TenneT operates the grid at its limits.

Grid congestion has been hampering the utility not only in the Netherlands but also in Germany, where numerous bottlenecks in the grid on land cause large wind farms in the North Sea to be curtailed and redispatch limits the generation of offshore wind power.

This not only affects the amount of electricity fed into the grid, but also impacts its price development.

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What more do we need?

In its Electricity Grids and Secure Energy Transitions report, the IEA states that globally we need to add or replace 80 million kilometres of power grids. Global investments in grids, which has otherwise remained stagnant, now needs upwards of $600 million annually a year by 2030.

Additionally, citing data from 2021, the report finds that grid-related outages impacted the German economy by up to $3.6 billion, highlighting the role of the grid in minimising economic loss.

Illustrated by the cases of the Netherlands and Germany, Europe is clearly seeing its fair share of hurdles to be overcome, but positive signs can still be found if you know where to look.

Take for example the EU Grid Action Plan, which will improve access to finance for grid projects. The action plan is also expected to identify tailored financing models and increase visibility on opportunities for EU funding programmes for smart grids and distribution modernisation.

Although much more, both in terms of euros and cabled kilometres, is needed to reach a grid fit purpose, we can still be hopeful as plans are pushed into action.

How much are you investing into the grid now and do you think it will be enough to enable the energy transition? Let me know.

Cheers,
Yusuf Latief
Content Producer
Smart Energy International

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In February 2024 Cyprus’s Electricity Authority, the state-owned energy company, awarded the tender for the smart meter rollout to CyTA at a cost of €39.9 million (US$43.4 million), according to a report in the Cyprus Mail.

However, the award was challenged by one of the other two bidders, Logicom Solutions, which had put in the lowest bid at €33.6 million.

The third from New Cytech Business Solution was at €37.6 million.

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According to the Cyprus Mail report, Logicom argued that in awarding the bid, the Authority had violated essential terms of the tender.

However, the Tenders Review Authority upheld the Electricity Authority’s decision, basing its finding on reasons of public interest.

The decision is quoted as reading: “Any further delay in implementing the contract would raise the spectre of serious repercussions both for Cyprus and for EAC customers, via the loss of financing from the European Union, by no means a paltry sum…”

In presenting the case Giorgos Petrou, chairman of the board at the Electricity Authority, had suggested that delays could raise the risk of Cyprus losing funds designated in the EU’s Recovery and Resilience Facility.

For those, according to the Cyprus Mail, the deal with the meter supplier must be finalised by March 2024.

Moreover, the Electricity Authority must receive 50,000 smart meters of which 15,000 are installed by September 2024 and by June 2026 all 400,000 smart meters must be received with 250,000 installations completed.

According to an earlier Cyprus Mail report, the Electricity Authority had earmarked a total of €50 million for the smart meter replacements, of which €35 million would come from the Recovery and Resilience Facility.

The same report also indicated that the 400,000 smart meters would correspond to about two-thirds of the metered base, with some customers staying with their traditional meters for cost or practical reasons, such as the elderly who felt that they could not effectively be served with them.

This is not the first time the rollout has been delayed. In April 2022 the bid was awarded to New Cytech but was challenged by Ningbo.

These can be organised in two clusters in which concrete business cases/good practices should be developed, namely:

• investment, access to capital and the regulatory framework, including the need to enhance grid resilience, and
• build-out prerequisites including supply chain, staffing, permitting, etc.

Actions and concrete recommendations can then be generated for tackling by the next European Commission, which commences on 1 November 2024.

In a letter from the three organisations to the EC Executive VP for the Green Deal Maroš Šefčovič following their participation in a dialogue on Green Deal infrastructure, they reiterate the core role of DSOs in delivering on its objectives with most of the renewables being connected to the distribution grids and the increasing electrification of heating and mobility.

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Key messages they state include the need to accelerate investment by mobilising private sector capital for energy and improving funding opportunities for DSOs at the national and EU levels and in particular enabling anticipatory investments with a forward-looking energy regulatory framework and tariff regime.

Permitting procedures must be further simplified, especially for grid capacity additions and upgrades, and initiatives to tackle the supply chain challenge are called for, including greater cooperation between grid operators and manufacturers.

The focus on resilient grids also must be reinforced to guarantee the security of supply at times of increasing (cyber)security threats and extreme weather conditions.

Against this, general principles suggested for the future are:

• Ensure national implementation of the European provisions to provide grids with suitable conditions for the delivery of the Green Deal objectives.
• Introduce ‘grids mainstreaming’ to ensure that grid expansion is not lagging behind, but that their needs are considered in every new and revised energy and climate act.
• Ensure regulatory consistency by promoting widespread consistency in acts that help DSOs achieve their objectives.
• Build a successful EU Alliance for the Green Deal Infrastructure to prepare the infrastructure for 2050 climate neutrality.
• Combine all of the above into a strategic technical roadmap for the future that has the support of all stakeholders.

Given the short time horizon until the next European Commission and the need for two more dialogues to be organised by the time of the EC’s June election, fast action is needed, the organisations state in the letter.

With this short-term horizon, the focus should be on these most pressing topics and after each dialogue guiding principles and recommendations should be issued on the contents for each cluster that can be implemented within a timeframe and mechanisms for reporting established.

They also comment that the dialogues should involve all levels, European and national and should be complementary to other often more technical initiatives.

Announced alongside the Group’s full-year results, E.ON plans to boost its four-year investment plan from €33 billion ($36 billion) to €42 billion ($46 billion), focusing on energy networks and energy infrastructure solutions.

“Across Europe, there are massive expansion plans for renewable energy facilities that will need to be connected to networks,” said E.ON chief financial officer Marc Spieker in a release.

“Millions of heat pumps, residential electricity storage systems, and charging stations will need to be installed as well. That’s why we’re investing even more and even faster in our power grid infrastructure, which is set to continuously grow by an average of ten percent annually through 2028.”

Within the plan, €34 billion ($37 billion) will go towards E.ON’s energy network business, given a suitable regulatory environment. More than €25 billion ($27.3 billion) – 70% – of network investments will be made in Germany.

Approximately €5 billion ($5.5 billion) will be devoted to energy infrastructure solutions, E.ON’s growth business which provides solutions for industries, cities, and municipalities.

Other areas for investment include digitalisation projects, the rollout of smart meters and intelligent e-mobility charging solutions.

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Said CEO Leonhard Birnbaum during a press conference: “We again defied challenging circumstances in the financial year 2023. And we again delivered very good results that exceeded our expectations.

“This result is proof … that we increasingly benefit from our consistent strategic focus on energy networks and sustainable energy infrastructure and customer solutions.

E.ON investment: 2023 results

The Group significantly accelerated its investments in the financial year 2023, bringing it a total of €6.4 billion ($7 billion), a one-third increase from the year prior.

Specifically, the Group invested €5.2 billion ($5.7 billion) in network expansion, modernisation, and digitalisation and €1.1 billion ($1.2 billion) into customer solutions, of which approximately €700 million ($765 million) went toward its energy infrastructure solutions.

Energy networks delivered the largest share of Group earnings from 2023 with a €1.2 billion ($1.3 billion) year-over-year increase. Higher investments in E.ON’s growing network infrastructure were a key driver, ensuring increased connection rates for renewables, heat pumps and charging infrastructure.

In 2023, E.ON added more than half a million new connections to its distribution networks. Alongside higher investments, the recovery of the energy market environment had a positive impact on the network business. This led to a significant reduction in costs for redispatch in Germany.

Added Spieker: “E.ON looks back on a strong financial year 2023, in which we grew in almost all European markets. The outlook for the years ahead is very promising as well.

“Our network business is a growth business that is in the focus of attention for policymakers, the public and investors. Our energy networks are system-critical for the energy transition, and we’ve again proven that we can successfully and cost-efficiently expand them.”

In 2023, Tennet invested €7.7 billion ($8.4 billion), split between its operating areas in the Netherlands at €2.9 billion ($3.2 billion) and Germany at €4.8 billion ($5.2 billion). According to the TSO in its fiscal results for last year, this represents a sharp increase in investments due to on- and offshore grid expansion.

The TSO is now saying it will continue to increase its annual investments, while also mulling the sale of its German operations to state-owned investment and development bank KfW, on behalf of the state.

According to reportage in the German Handelsblatt, the state sale has been in negotiation between the federal and Dutch governments for months.

The TSO belongs to the Dutch state, although a large part of its grid operations are located in Germany and run by a TenneT-owned subsidiary, also named TenneT. The state negotiations concern the sale of said subsidiary.

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Flailing grid capacity

Although TenneT reports healthy financial results of €1.8 billion ($2 billion) in earnings before income and tax, up 50.2% year-over-year, over the course of 2023 underlying revenues decreased by €600 million ($655 million) to €9.2 billion ($10 billion), driven by a decline in ancillary service costs.

These costs come from lower market prices for costs incurred by TenneT to compensate for grid losses, maintain the energy balance in the grid and pay for alternative electricity routes in case of congested or unavailable grid sections.

In the Netherlands specifically, the power grid has continued to reach capacity, despite record investments from its operators last year. According to Alliander, traffic jams will recur on the Dutch electricity network for at least another 10 years.

In June 2023, the Dutch state provided €1.6 billion ($1.7 billion) to TenneT to cover the funding requirements of its Dutch operations.

Additionally, states TenneT, as there is no certainty of the German sale materialising in the short term, the Dutch state has also provided a bridge loan facility of €25 billion ($27.3 billion) in 2024, safeguarding TenneT’s planned investments in both countries for 2024 and 2025.

According to Handelsblatt, Tennet CFO Arina Freitag promised a sale within the next 12 months.

Said Freitag in a statement: “To achieve a futureproof energy system for a competitive and climate neutral economy halfway through this century, we must sustain investment momentum. Balancing economic efficiency, sustainability and a high level of grid availability expected by our end-customers in the Netherlands and Germany requires a massive grid expansion.

“For TenneT this adds up to an investment programme of as much as €160 billion ($174.8 billion) and requires a consistent energy policy and solution-orientation from all parties involved.”

50Hertz, a Berlin-based system operator, announced their investment intention in response to the increasing amount of renewables coming online, resulting in increased demand for transmission capacity.

During a press conference, the operator said they integrated more renewables last year into the electricity than ever before. A total of 72% of electricity consumption across its grid area, they added, was met by renewables – the highest level ever – and now more transmission lines need to be reinforced or built to relieve grid congestion.

“50Hertz is entering a new phase in its corporate history. Its focus is shifting from planning and permitting to investment, construction and delivery. And we are making good progress in these areas”, said Stefan Kapferer, CEO of 50Hertz, at the TSO’s annual press conference in Berlin.

“We are preparing ourselves for the enormous efforts that will be needed well into the 2040s to make our transmission grid fit to meet the German and European climate protection targets. Faster grid extension and acceptance of the energy transition can only be achieved with greater cost efficiency.”

Commenting on the financial structure of the planned investment, Marco Nix, the utility’s chief financial and investment officer, said “Listed bonds remain the backbone of our capital structure.

“Around 60% of these relate to debt financing, like the two green bonds which amount to €1.5 billion ($1.6 billion), which we were recently able to successfully issue on the market. For the long-term success of the company, a solid development of equity and net result are also necessary.”

In 2023, 50Hertz invested €1.7 billion ($1.9 billion) in grid infrastructure and achieved an annual result of €220 million ($240 million) with equity strengthened by over 10% with shareholder support.

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Transmission buildout

Germany’s network development plan lays out transmission capacity needs, including 4,800km of new lines and reinforcement of 2,500km across the country.

50Hertz specifically, whose grid area covers the eastern German states as well as Berlin and Hamburg, has completed around one fourth of development measures for the onshore transmission grid, amounting to more than 800km of lines. Another 560km are currently being built.

This year, the company will also complete other important construction projects and commission a number of lines, including the Nordring Berlin project; the offshore grid connection for the Baltic Eagle wind farm (Ostwind 2); and the Uckermark Line, an important regional north-south connection between the Baltic Sea and the larger Berlin area.

In terms of offshore development, the plotting work for the Ostwind 3 project, which will connect the 300 MW Windanker wind farm to the mainland, has begun.

2024 also sees the company undertake preparatory work on line crossing under roads and railroad lines, including the SuedOstLink extra-high-voltage direct current transmission line between the Wolmirstedt and Isar substations near Landshut in Bavaria.

In future, 50Hertz’s on- and offshore grid is expected to grow by around 4,000km, provided that all projects included in the 2037/2045 Grid Development Plan were confirmed by the Federal Network Agency are included in the Federal Requirements Plan Act.

The 44 projects, selected from 53 that were submitted for round three of the fund, will be led by energy network companies in partnership with innovators and partner organisations.

Priority challenges for eligibility included:

• Whole system planning and utilisation of networks, to facilitate faster and cheaper network transformation and asset rollout;
• Novel technical, process and market approaches to deliver an equitable and secure net zero power system;
• Unlocking energy system flexibility to accelerate the electrification of heat;
• Enabling power-to-gas (P2G) to provide system flexibility and energy network optimisation.

Project delivery

The SIF, funded by energy regulator Ofgem and delivered by Innovate UK, aims to find potential ideas for energy network challenges and identify those with the greatest promise as quickly as possible.

With their selection into the funding programme, the 44 projects will now enter their initial discovery phase. If successful, they will help customers and the wider electricity sector accelerate their net zero plans, build network resilience, access lower costs and streamline maintenance activities.

In a release, UK Research and Innovation (UKRI), which directs research and innovation funding in the UK, lists examples of selected network and flexibility projects:

Equiflex

Led by SP Energy Networks, Equiflex aims to promote equal access to flexibility markets, ensuring a just transition to net zero.

Equiflex project partners, Frazer-Nash Consulting Ltd, Energy Action Scotland and East Ayrshire Council, are looking at the design of flexibility options targeted at specific groups, such as less engaged and more vulnerable consumers.

They are also looking at the development of a toolkit to help stakeholders, such as local authorities, to evaluate which flexibility options might be best for their local context.

B-Linepack+

The B-Linepack+ project, led by National Gas, is exploring the feasibility of using geological solutions as intermediate scale storage.

The national gas transmission system can pack additional gas into the lines, known as linepacking. However, the amount of energy able to be stored by linepacking will decrease as we move toward decarbonisation of the networks with the use of hydrogen.

The project works with partners from the University of Edinburgh, Gravitricity Ltd, Southern Gas Networks, Revolutionary Engineering & Digital Design Ltd and Energy Reform Ltd.

It is looking at how lined rock shafts, engineered rock caverns and underground silos could provide purpose-built storage to supplement linepack capacity and provide system flexibility. This will enable supply and demand to be managed more effectively for consumers.

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UKPN flexibility projects

Additionally, UK Power Networks listed three projects selected for funding, including:

• Electric Thames: exploring the viability of electric-powered boats on the River Thames, and the possibility of boat power feeding the electricity grid to increase energy flexibility and reduce peak electricity demand
• KnowMyFlex: a proposal to create energy flexibility certificates, similar to energy performance certificate (or EPC) ratings, to show the existing and future flexibility potential of homes and buildings, helping customers engage with flexibility to reduce their bills
• WASH: an advanced study into the ways heat can be efficiently captured from wastewater and used to help district heat networks decarbonise

Luca Grella, head of innovation at UK Power Networks, said: “We’ve made remarkable strides during our first year with the SIF programme and are excited to be heading into a second with a new wave of projects which have exciting potential to make a real impact on both our communities and the way we work.

“This funding is allowing us to continue building strong bonds with some of the brightest minds in the sector. Our project collaborators play a key role in helping us deliver tangible benefits for our customers, and we can’t wait to reap the rewards of these partnerships.”

Launched in 2021, the UK‘s SIF fund is expected to invest £450 million ($577 million) by 2026.

According to Alliander, traffic jams will recur on the Dutch electricity network for at least another 10 years.

Alliander, Enexis and Stedin, three distribution system operators in the Netherlands, each stated in their Q4 results record levels of investments into the power grid system in attempts to accommodate demand growth.

Alliander invested more than €1.4 billion ($1.6 billion) in 2023 on 2,207 transformers, 2,518km of new medium-voltage and low-voltage cables and 304km (2022: 255km) of gas pipelines.

Enexis spent €1.214 billion ($1.327 billion) on its grid, an increase of 18% from the year prior, installing approximately 1,350km of electricity cables and more stations.

Stedin invested €832 million ($909 million) in the expansion and maintenance of their grids, €120 million ($131 million) more (by over 17%) than the previous year, on 892km of power cables and 266 new transformer substations.

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A call to action

In 2023, states Alliander, it became clear how dire the situation is on the Netherlands‘ electricity grid; the network is under great pressure and has reached capacity multiple times during peak demand periods.

The company cites significant growth in clean tech assets, such as heat pumps, solar panels and e-boilers, as well as the electrification of business processes and installation of charging points for passenger transport and electric trucks, all of which continued in 2023.

This, alongside sustainable construction initiatives – making new and existing homes more sustainable by relying on clean technologies – will add heavy demand to the power grid.

Alliander also cites a shortage of technical staff, lengthy procedures, insufficient available space in the public environment and a lack of system choices that hinder further scaling up; to accelerate further where possible, stricter choices are needed.

Stedin, on the other end, calls on consumers, businesses and governments to jointly reduce the pressure on the power grid and make optimal use of renewable energy sources.

Said Koen Bogers, CEO of Stedin: “Stedin does everything within its capacity to expand the power grid…But that won’t be enough. Particularly in the evening peak, between 16:00 and 21:00, and on sunny spring and summer days, the grid is bursting at the seams.

“This is becoming a growing social problem. We ask consumers and businesses to adjust their behaviour and consider when they need a lot of electricity. For consumers, Stedin is launching an awareness campaign for this in March.

“After all, the moment you use power has become an important consideration. If we change our behaviour, grid operators can free up more capacity, which can then be used to connect businesses on the waiting list, as well as new-build homes and schools.”

In their statement, Enexis added that, despite the surges in demand and subsequent bottlenecks, Dutch businesses can still make use of the grid via flex contracts, interest in which has been increasing.

Through the contract, willing companies shift their production processes to the night, share electricity with a neighbouring company or instal batteries to make their business case possible.

Said Enexis CEO Rutger van der Leeuw: “We are also learning more about this every day and are developing new types of contracts to give customers a perspective for solutions.”

With opinions ranging from AI to electrification and renewables, as well as plays made by non-traditional entrants, this edition of Smart Energy’s Power Playbook lays down how experts analyse the evolving energy market.

Digital adaptation

According to Brad Johnson, director of solution management for tech company Bentley, a key talking point has been blending in automation, from AI – the core focus during the DISTRIBUTECH conference – to machine learning and augmented reality.

“One of the trends we’ve noticed professionals talking about is how to blend all these technologies into utility practices in a way that’s approachable for professionals.”

To do so, he adds, human assistance will be crucial as a “first step into automation. Rather than just pushing the button and trusting the output will match, it means keeping close supervision on the technology.

“AI and ML technologies will offer that ability to peer into the process, provide supervision and remove barriers to adoption.”

Hitachi Energy’s Steven Kunsman and Tanya Wright also highlighted this push into the digital environment.

Wright, a vice president of marketing and communications, comments on Hitachi’s moves to “transform itself as a global conglomerate and become more digital, because they see that the world is transforming and changing and moving toward digitalisation across all industries, including energy.”

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Referencing combined capabilities from Hitachi Energy, Hitachi Ventara (an IT services management company) and GlobalLogic (a digital engineering company acquired by Hitachi in 2021), the two reps comment that digital transformation has been a key thought in the mind of companies looking to grow.

Says Kunsman, head of global product management: “There’s competition and companies are looking to answer the question of (how to) position themselves…Utilities will be going through a huge transformation with their operational technology, including substations, where digitalisation and connectivity will lead this change.

“Increasing levels of renewables penetration and distributed energy resource (DER) plants are connecting to grids that traditionally were not designed for DER interconnection.

“For these changes, companies need to review their portfolio and solutions offering to identify gaps and develop strategies to either fill those gaps through various acquisitions or develop those capabilities within the organisation.”

Kunsman adds: “The biggest trend right now is the transition to clean energy and deployment of EV infrastructure. And from that perspective, every utility will have a role in this major transformation to be able to support this type of change in the marketplace.”

Electrification and the EV era

Kunsman’s commentary on digitalisation and EV interest came as no surprise. Utilities have increasingly recognised the increasing urgency of consumption management on the power grid as a high priority.

However, says Garret Fitzgerald of the Smart Electric Power Alliance (SEPA), although its importance is clear, this clarity is a recent phenomenon.

Fitzgerald, a senior director of research and industry strategy for transport and electrification, says that its importance only came onto the table over the last four to five years:

“I’ve been in this market for about 15 years and 10 years ago I started talking to utilities and advising them on the upcoming load growth from EVs and the subsequent planning that will be needed. But for five of those 10 years, most utilities said ‘It’s not a big deal. If they come, we’ll manage it.’”

Citing European policymaking and mandates for vehicle electrification, Fitzgerald says that signals are now being sent to OEMs to “invest billions and billions of dollars in battery manufacturing and EV lines.

“With all of that coming together at a global scale, utilities are recognising that the EV wave is here.

“When you see some of the sales figures for EVs – 25% in California and 10%, across the US – we see that it’s real.

“The biggest trend I’ve seen is that transition from three or four years ago of utilities being unsure of the EV transition to now acknowledging the need for load planning from their uptake and what this means for the distribution system and what it will require of regulators.”

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Renewable integration and non-traditional players

Of course, it is not only EVs that represent a significant load management challenge.

According to S&P Global analysis, clean energy technology investments in 2024 will rise by 10%-20% compared with 2023, with renewables continuing to take the lion’s share. This uptake was repeatedly cited as a key market focus.

“There is a much greater interest in integration of renewables than in the past and it’s growing all the time,” commented Phil Beecher, president and CEO of Wi-SUN Alliance, a California-based consortium of global corporations in the smart utility, smart city and IoT markets.

“Storage and EV charging continue to be areas of interest … However, we’re seeing huge growth in renewable activity in emerging countries, such as India and Latin America, where it seems to be taken very seriously.”

Echoing Beecher’s sentiments was Bryan Sacks, global CTO and solution leader for energy, environment and utilities at IBM, a tech company focusing on hybrid cloud and AI solutions.

“What I’m finding really interesting is non-traditional entrants into the energy market – for example, traditional oil and gas players – who are starting to invest heavily into technologies, such as batteries, EV charging stations and renewable generation.

“For example, we’ve started to see companies like Walmart, which has massive roof space for solar, looking at deploying this type of technology.”

According to Sacks, it is also worth watching how the energy market will evolve to take advantage of these new entrants.

“What impact is that going to have on the traditional energy regulated components of the marketplace that don’t necessarily have the same flexibility?

“The evolving interplay between the regulated market and other growth markets, as well as how utilities invest in non-regulated areas to take advantage of those spaces, will become fascinating to watch.”

Were you at DISTRIBUTECH International? What were your key takeaways and what are some of the most interesting trends you’ve seen emerging?

Let me know.

Cheers,
Yusuf Latief
Content Producer
Smart Energy International

Follow me on Linkedin

The $1.3 billion target facility is focused on improving strategic interconnection and cross-border energy transmission in the Southern Africa region.

The facility, which launches with $20 million in commitments from SAPP, targets a first close of $500 million in 2025 to be raised from public and private sector investors locally and internationally, as well as a final close of $1.3 billion within 24 months. The facility will have a fund life of up to 20-25 years.

RTIFF will prioritise projects that focus on connecting currently unconnected SAPP members, help relieve congestion bottlenecks to regional electricity trading, promote inter-continental power trading through transmission corridors and support the adoption of new-generation renewable energy space in the region.

According to Climate Fund Managers, energy transmission infrastructure projects are notoriously high-risk and capital-intensive, making them challenging to fund independently through sovereign capital alone.

To battle this, the facility makes use of a blended finance model, utilising public capital to balance risk and enable private capital to enter.

The fund’s architecture follows the structure of CFM’s emerging market blended finance facilities Climate Investor One, focused on renewable energy generation and transmission, and Climate Investor Two, focused on water, sanitation and ocean infrastructure.

It will comprise a $100 million target ‘Development Fund’ to provide concessional capital and development expertise, including support on viability studies, legal and financial structuring, planning and ESG compliance.

It will also include a $1.2 billion target ‘Construction Fund’ that will make direct investments through the provision of construction financing and value-add expertise for transmission project builds.

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Improving transmission between member states

Victor Mapani, chairperson of the SAPP Executive Committee, said in a release: “The provision of sustainable power can be distilled into three activities: generation, transmission and distribution. While generation receives the lion’s share of attention, the importance of delivering that power to where it is needed is equally critical.”

The facility is hoped to improve energy transmission within and between the 16 SADC member states and with other power pools.

SAPP is a cooperation of 12 Southern African countries represented by their national power utilities and some private utilities under the auspices of the SADC.

SAPP members Angola, Botswana, Democratic Republic of the Congo, Eswatini, Lesotho, Mozambique, Malawi, Namibia, South Africa, Tanzania, Zambia, and Zimbabwe have already created a common power grid between their countries.

The SAPP also operates a competitive electricity market in the SADC region and the RTIFF will provide power companies and project developers working on transmission issues with access to patient capital and development expertise to establish strategic interconnections that allow for increased electricity trade.

Added Mapani: “Access to capital is the number one barrier facing developers of energy transmission infrastructure. RTIFF dismantles this by enabling the private sector to work alongside public sector utilities to roll out new transmission lines at scale.

“We are delighted to have appointed CFM with their strong track record in the African energy sector to establish and manage this innovative facility and to help our member states finally secure a sustainable, resilient energy supply.”

Stephen Dihwa, Coordination Centre executive director of SAPP, said: “Interconnection across SAPP via strategic transmission corridors can save the SADC region an estimated $37-42 billion in Net Present Value (NPV) by 2040. We have identified eight high-priority transmission projects for RTIFF that will bring economic benefits of $4.3 billion in NPV.”

Added Amit Mohan, head of Private Credit at CFM: “The lack of investment in grid infrastructure is one of the reasons for ongoing blackouts in many parts of Southern Africa…If we don’t invest in grids today, we will face gridlock tomorrow.

“This is even more pressing from an energy transition perspective as the world needs to embrace green electrons on the grid. CFM is proud to be associated with SAPP and appointed as the manager of RTIFF as there is a deep need to mobilise blended finance at scale and speed to enable the rollout of additional grid infrastructure in the region.”

CER refers to smaller-scale energy resources owned by customers, which can produce, store, or vary how they use energy. Newer forms of CER include clean tech assets such as solar panels, batteries and EVs, as well as more traditional assets such as hot water heaters and pool pumps.

As part of a broad set of reforms, the AEMC announced a priority for customers to make better use of these CERs and contribute to grid stability.

In a release, AEMC chair Anna Collyer said investing in these resources empowers consumers to generate, consume, store and trade energy according to their preferences.

“By using these assets in a smart way, customers can lower their energy bills, and should they choose, share the power they generate or vary their consumption in such a way that it supports the overall grid,” said Collyer.

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A draft determination paper by the AEMC outlines positions on how to unlock the benefits of CER, with new arrangements made for:

• ‘Flexible’ trading by enabling all customers to have CER separately metered and therefore identified and managed separately from other ‘passive’ consumer loads such as lights and fridges.
• Large customers choose multiple energy service providers for their premises.
• An in-built measurement capability in technology such as streetlights and EV chargers to be used instead of additional meters, which allow for the measurement and management of energy use at lower cost.

The AEMC states the reforms as part of their work to create greater visibility of price-responsive resources, such as household batteries, making it easier for customers to participate in the power market, while helping AEMO and networks to operate the system more efficiently.

Added Collyer: “The key to a successful transition is integrating these resources effectively into the National Electricity Market. Our only choice is to be well prepared.

“If we do not properly integrate CER into market processes, we face materially higher generation, network and intervention costs. Consumers have a critical role in the transition – but to do so – they need sound policy decisions from us all.”

Further network reforms discussed in Canberra

Days following the announcement from the AEMC, The Energy and Climate Change Ministerial Council (ECMC) met in Canberra, Australia, and committed to undertaking reforms on network planning through a National Consumer Energy Resources Roadmap.

The roadmap will deliver reforms on new consumer protections, network reforms to allow consumers to export more solar power to the grid, as well as nationally consistent standards in key areas, including vehicle to grid (V2G) technologies.

By doing so, states the Council in a communique, downward pressure will be placed on overall system costs and consumer bills, while contributing to emissions reductions and broadening access to CER.

According to the communique, reforms in each of these areas are already underway, such as those being coordinated by the AEMC, including streamlining connection processes, making Service and Installation Rules nationally consistent, and establishing standards and a regulatory framework for CER.

In response to the statements, Energy Consumers Australia CEO Brendan French commented in a release:

“Energy Consumers Australia welcomes today’s announcement that governments will develop a consumer-focused reform package to present at the next energy ministers meeting in July.

“There are just too many barriers that prevent people getting better energy deals, particularly people in financial stress or experiencing disadvantage. Pricing structures are too complex and it is difficult for consumers to understand the terms they see on their bills.

“Our research has found that 32% of homeowners and 44% of renters say they are unsure which tariff structure they are on. Many people simply cannot participate in a market as arcane as this one.

“We also support the government’s commitment to undertaking reforms through a National Consumer Energy Resources Roadmap. There are many instances now where people and communities are not only consumers, but suppliers of energy and they should be fairly rewarded for the generation, storage and services they provide to the system.”

The European Commission is making available €74 million (US$80 million) in funding towards the creation of the energy and other sectoral data spaces as part of an over €176 million ($191 million) package for the Digital Europe 2023-2024 work programme.

The sectoral data spaces, a key component of the EU’s data strategy, are intended to form repositories for pooling, accessing, sharing and processing data from within the respective sectors from across the EU.

Based on common data infrastructures and governance frameworks, their evolution is being driven by users within their respective sectors.

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Over time the goal is for them to be gradually interconnected, furthering the data sharing – for example, energy with mobility opening the energy sector to wider participation – and ultimately forming a single market for data that can assure Europe’s global competitiveness and data sovereignty.

Energy data space

With various initiatives well under way towards the energy data space, proposals for the 2023-2024 programme should foresee the deployment of the first version, building on these, in at least ten member states with piloting of at least five use cases in areas such as distributed energy resources management, provision of flexibility services for electricity grids or smart and bi-directional electric vehicle (EV) charging.

These should use a commonly agreed reference architecture with replicable and scalable building blocks, e.g. on data models and formats, data exchange APIs, data provenance and traceability, metadata, etc.

In particular regarding data interoperability arrangements, the data space should be based on agreed minimal interoperability mechanisms that will align energy-relevant key stakeholders on a set of minimal sufficient capabilities needed to achieve interoperability of data, systems and services between the key players of the energy value chains at all levels, i.e. European, national and local.

Another requirement is the consideration of a complete set of open standards, while other deliverables required are the definition of suitable business models that can ensure financial sustainability of the energy data space beyond the end of the project and the implementation of a governance system for overseeing its operations.

An amount of €8 million ($8.7 million) is allocated for this energy data space advancement, which is expected to take place over 36 months.

In addition to the support for the data spaces, the €176 million package includes funding to advance research and use of artificial intelligence, for projects on the cloud to edge infrastructure and for skills development.

Pacific Gas & Electric (PG&E), the largest utility in California, is partnering up with energy software business Kaluza and EV charging company Wallbox to pilot the smart charging and Vehicle to Everything (V2X) technology.

Through $1.5 million in phase one funding from the California Energy Commission (CEC) REDWDS grant, the partners will develop new technologies to incorporate dynamic price signals for both one-way ‘V1G’ and bidirectional ‘V2X’ charging.

The project will allow drivers to ‘set and forget’ their EV charging: using Kaluza’s algorithms, a smart EV charger, driver preferences, live grid data and dynamic pricing structures, vehicles will charge optimally to reduce grid pressures during public safety power shutoff events.

The programme will comprise 330 vehicles, with a commitment to deploy at least 50% of these assets in low-income communities.

Some of these assets will be connected to Wallbox’s bidirectional charger, Quasar 2, enabling users to charge their EVs and export power back to their homes or offer emergency back-up power when the grid is down. EVs store around 70kWh in their battery – sufficient to power an average home for three days, longer than most stationary batteries.

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Project progression

If the project is successful, additional CEC funding of up to $4 million will be made available through a second phase to continue deploying managed charging and bidirectional solutions in California.

Mike Delaney, vice president of Utility Partnerships and Innovation at PG&E, commented on the V2X partnership in a release: “Our work to prepare the grid to power and support millions more EVs over the next decade includes creating the most robust vehicle-grid-integration portfolio in the world.

“To that end, we are collaborating with the best and the brightest to integrate new bidirectional charging capabilities and to provide the platform, expertise, and cross-industry leadership to enable our customers with a range of options that unleash the full potential of their EVs.”

Phase 1 of the three-year pilot kicks off this year, with customer enrolment expected at the end of 2024. The programme operation and data collection will extend through September 2026.

PG&E provides natural gas and electric services to approximately 16 million customer, with 600,000 operating EVs throughout the utility’s Northern and Central California service area.

In a release, the partners cite high initial costs and the reliance of low-income individuals on their vehicles for work, posing challenges for these communities in transitioning to EVs. The project partners will further collaborate to lower the upfront costs of switching to an EV and showcase the efficiency of managed charging programmes in ensuring affordable charging and constant vehicle readiness for customers.

Additional partners in the initiative include community-owned electricity provider Sonoma Clean Power and Valley Clean Air Now (CAN). The former aims to make EV charging more accessible for low-income communities and the will support customers in learning about options to make use of second hand EVs.

Jonathan Levy, US managing director at Kaluza, commented: “We are thrilled to be selected for up to $6.2 million in funding from the California Energy Commission, enabling Kaluza to accelerate our work in the United States.

“With California rapidly approaching 2 million cumulative EV sales, managed charging with software solutions like Kaluza means everyone’s a winner – including EV drivers, utilities like PG&E, the grid and the planet.”

The rollout follows the regulatory approval given in September 2023, which authorised up to $153 million for the initiative and forms part of Rhode Island Energy’s grid modernisation activities to enable the integration of renewable energies to support the state’s climate goals.

The Revelo metering platform features grid edge sensing and edge computing capabilities to manage load and support grid troubleshooting, with the Revelo meter operating on Landis+Gyr’s RF Wi-SUN network.

Additionally, the advanced grid-edge processing allows for greater consumer engagement with applications such as real-time load disaggregation and pricing information.

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“The Commission’s approval to implement our advanced metering plan is an important step in modernising the state’s energy infrastructure for the benefit of all Rhode Islanders,” said Dave Bonenberger, president of Rhode Island Energy, of the approval.

With the prospect of being able to benefit from parent company PPL Corporation’s other smart meter rollouts in Pennsylvania and Kentucky, he continued: “We’ve seen the success of these new technologies across other PPL service territories, and customers should be excited about the advantages they’ll bring to their homes and businesses.”

The rollout is timely as approximately 60% of the electricity meters across the state are nearing the end of their design life and need to be replaced.

Before the start of the rollout, which is expected to begin in 2025 and to be completed over the following three years, Rhode Island Energy intends to engage customers to provide more details about the technology in advance of installation, as well as an opt-out option.

In October 2023 Rhode Island Energy was selected to potentially receive up to $50 million in federal funding from the Infrastructure Investment Act towards its almost $300 million smart grid investment programme to improve visibility and control on its grid.

Among the plans are advanced distribution management and energy management systems and a centralised asset hub data system and geographic information system to represent a digital twin of the grid.

The rollout, launched in 2015, has seen a J$14 billion (US$90 million) investment as part of the initiative to modernise the electricity network and improve the customer experience.

Since late 2023 the project primarily focussed on St Mary parish, to the north of the capital, Kingston.

Other parishes on this eastern side of the island, including Portland and southern sections of Kingston and St. Andrew, are due to be completed later this year.

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Smart meter customers can track their consumption with the company’s MyJPS mobile app and also benefit from other services including remote connection/disconnection and account transfers and switching between postpaid and prepaid options.

“Our ongoing future-oriented approach, underscores our dedication to providing faster, more efficient service,” said Pia Baker, Senior VP of Customer Experience and Commercial at JPS.

“We are proud of the progress we have made and the positive impact it is having on our customers’ experiences.”

Under a 2018 agreement, Itron was contracted to extend the existing Gen 5 network to support the full 670,000 smart meter deployment, while the smart meters were being provided by Aclara.

In other news, JPSCo has been awarded a US$100 million financing package from IDB Invest for its 2024-2025 investment programme for the ongoing modernisation of its grid, including the smart meter deployment and transmission and distribution upgrades, and the expansion of access to new customers.

Additionally, the funding should support JPS’s continuing digital transformation through cloud-based solutions as well as the island’s electric vehicle (EV) infrastructure development, including 17 new EV charging stations.

These are expected to support a rapid rollout of renewable energies and storage technology.

Currently, approximately 14% of Jamaica’s energy supply is renewable, primarily hydro, wind and solar.

This was the consensus of panellists who participated in a discussion at the Africa Green Economy Summit in Cape Town, South Africa.

According to Marketsandmarkets, the global Battery Energy Storage System (BESS) market is expected to grow to $17.5 billion by 2028, and while Africa is looking to tap into this growing market, the continent first needs to overcome challenges to building a home-grown battery supply chain.

Mitigating cost through partnerships

Setting up a battery precursor facility is costly and one panellist who knows about that risk is Deshan Naidoo, managing director of Afrivolt.

Afrivolt is developing Africa’s first lithium-ion cell manufacturing facility with a 5GWh installed capacity. The gigafactory will likely be located in Cape Town, South Africa.

According to Naidoo, it will require about $100 million per GWh installed, which indicates the significant foreign direct investment needed to unlock this opportunity.

The good news, explained Naidoo, is that there is a lot of capital available from local and international investors and even though the cost of localising these production facilities is high, there is tremendous economic value added by localising this technology.

The key is partnerships, he said.

Naidoo explained: “We are not going to achieve this energy transition or localisation of the value chains unless we are able to achieve international technology partnerships,” adding that Africa has never been a leader in terms of technology development so an emulation strategy makes sense.

“Afrivolt has built up these partnerships around the cell manufacturing side and on the battery precursor side,” such as US partners that can tailor the cathode chemistry based on local mineral deposits.

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Current opportunities and challenges

Panellists agreed on the importance of partnerships but identified several challenges hindering progress.

Nathan Fredericks, Industry Development Planner: Office of the COO at the Industrial Development Corporation of South Africa, stated that for an international OEM to consider partnering, policy support, evidence of supply chain, and capital must be evident.

And while the continent, and more specifically South Africa, is making headway in this regard, there is still work to be done, they agreed.

To encourage investment and development, special economic development zones are being established across Africa. These zones, according to panellists, are focus areas for investment designed to establish the infrastructure and logistics needed for effective supply chain functioning.

Maidei Matika, chief investment facilitator at GIDZ, emphasised the importance of these zones but explained that to develop facilities within them, power, water, sewage etc. are needed – and in South Africa, for example, there is a big problem with a lack of power generation capacity.

This makes it tricky, said Matika, because they are promoting investment opportunities while simultaneously finding solutions to the local challenges that ultimately hinder investment. “It’s two sides of the same coin, you are wanting a green economy and renewable energy solutions…and without that, you can’t promote the production you want to see”.

The fact that the battery value chain runs through several sectors and other value chains also brings a unique set of challenging dynamics said Fredericks, not to mention the role of geopolitics, the lack of political will and competition with China.

In terms of South Africa, added Fredericks, the country has a vibrant energy sector, good industrial roots, and demand pathways. And even though the battery industry is still nascent and skills still need to be developed, it’s possible to leverage the country’s deep industrial base to maximise local supply chain development.

A working partnership

There are examples of successful partnerships spurring the development of Africa’s battery supply chain.

Zitto Alfayo, head of project preparation at Afreximbank UK, highlighted the partnership between the Democratic Republic of Congo (DRC), home to lithium and cobalt resources, and Zambia, which is well endowed with manganese and copper.

Around 2021, explained Alfayo, as discussions about electric vehicles gained momentum across the continent, Afreximbank started exploring opportunities to start manufacturing locally, rather than merely exporting minerals abroad.

Ultimately, Afreximbank, the United Nations Economic Commission for Africa (ECA), the Democratic Republic of Congo and Zambia formed an agreement and established a special economic zone for the production of battery electric vehicles and related services.

This was a first on the continent, said Alfayo, adding that “through this kind of intervention, the cost of producing and setting up a battery precursor plant on the continent was three times cheaper than in the US or China”.

“This makes a lot of sense from an economic perspective,” he said.

Setting up a fully-fledged industrial plant via a special economic zone allows Africa to be strategically positioned up the value chain and positions the continent strategically to produce batteries for the continent and globally.

And thus far, the partnership is proving successful in that regard, said Alfayo, adding that they have recently secured international partnerships with the likes of China.

Panellists agreed that the cost and challenges are evident but the opportunities for Africa are transformational.

Concluded Alfayo: “We have all the ingredients that can power the energy transition…there is an opportunity to reimagine, reinvent and reposition how Africa goes about the energy transition.”

According to Market Reports World, the global Home Energy Management Systems Market is expected to witness substantial growth from 2022 to 2028, reaching $3.5 billion by the end of the forecast period, up from $1.7 billion in 2021.

Fuelled by the increasing importance of intelligently managed energy efficiency for our power systems, the forecast for its growth is no surprise.

The potential of under-utilised sources of demand response within the residential sector has been a growing business interest as countries investigate newer, smarter ways of managing grid congestion.

What this has led to is a business battleground and, until recently, a largely fragmented market.

In one corner stand the original equipment manufacturers (OEMs) of clean tech assets, such as Heating, Ventilation and Air Conditioning (HVAC) systems, EVs and their charge points, as well as heat pumps and solar PV panels, to name some of the most popular.

In another are the optimisers and integrators, those companies who coordinate the flows of energy for optimal consumption, at times running interface with grid operators for demand response and flexibility services.

Then finally, we have the energy retailers, who buy electric power from generators at the wholesale level on behalf of their customers.

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For all these players, key to gaining market share will be convincing their customers that their products or services within the space are the most seamless.

For some, take market leaders such as Tesla or Octopus Energy, doing so largely on their own terms has been a very viable course of action.

But for others, whether HVAC providers, smart thermostat manufacturers or PV specialists and energy optimisers, more strategic footwork has been necessary, calling for acquisitions and strategic partnerships to consolidate their positions.

“The real war is about who will take ownership of being the ones that will convince the end customer to use their assets or their services.” So stated George Husni, LCP Delta’s head of business development.

Industry edge

According to Husni, in the battle between smart thermostat manufacturers and HVAC players, the former innovated user interfaces earlier giving them an edge, whereas “HVAC players lagged behind in developing the mobile application for end customers.

“We believe that within five years’ time integrated PV specialists, like 1KOMMA5°, as well as energy suppliers are expected to gain market share by offering a suit of solar-related offerings and innovative business models; smaller installers will be acquired and will phase out of distribution because they will not own the relationship with the final customers.”

Husni referenced key partnerships, acquisitions and strategic moves from the last quarter. Including a consolidation by emobility giant and Texas-based OEM Tesla, who has long dominated the EV realm, in 2023 they integrated the Powerwall system with their EV solar charging infrastructure.

In essence, Tesla owners using Tesla software, namely the Charge on Solar programme, can charge their vehicle using only excess solar power generated by their panels, alleviating stress from the grid of charging the EV and leading to a more energy-efficient home.

Tesla can thus be said to be a go-to case of an OEM leading the market on their own terms, consolidating their business across the Home Energy Management segment while maintaining their position as the EV leader.

Dominance in the realm also brings to mind the case of Octopus Energy, an energy supplier which, under its own retail brand, delivers customer service and energy products to 7.7 million households globally. Add in the influence of Kraken Technologies, Octopus’ tech arm and customer platform, and it is no wonder that the British player has been at the forefront of news headline the past few years.

According to Husni, there is a certain level of ‘concern’ about retailers in the market, about if and when they would decide to properly engage, as they already have an advantage from data and relationships from their customer base; a point made more pertinent by Octopus Energy’s stature.

But, of course, not everyone can be a Tesla or an Octopus.

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Home Energy Management: Consolidatory moves

Husni stressed key moves that have been needed by PV specialists in Europe, such as 1KOMMA5°’s acquisition of solar installers Zonduurzaam to enter the dutch market and experta solar to consolidate in Spain, as well as SolarEdge’s partnership with European heating manufacturer Vaillant to integrate Vaillant heat pumps into the SolarEdge Home ecosystem.

Further cases include the GridX and Sense partnership, focused on leveraging smart meters to provide consumers and utilities with better insights into energy usage and costs, as well as Sonnen integrating Nibe heat pumps into their virtual power plant programme.

On the energy supplier side, states Husni, Heatio partnered with E.on to provide its Energy as a Service solution through a home subscription product. The solution will integrate E.ON Next energy tariff and incentivises homeowners to improve the energy efficiency of their homes.

Take also Samsung’s smart home platform SmartThings, which partnered with energy related companies, such as Eve Systems in 2023 and British Gas earlier this year in January, to integrate products and track consumption.

In the partnership with Eve, SmartThings users will have the ability to reduce power consumption by monitoring individual devices that are connected to Eve’s smart plug, reducing utility bills by creating automation routines and setting timers to optimise energy usage.

The partnership with British Gas, described by British Gas’ parent company Centrica as “the exciting first step in a long-term venture”, sees British Gas’ PeakSave demand flexibility scheme integrate with SmartThings Energy, informing customers on the best times to use appliances to save money.

An energy integrator here, Samsung’s moves further cement its position in the market as an energy flow coordinator, interfacing both with energy companies and utilities to oversee consumption.

Such cases demonstrate the moves market players make to cement their position in the home energy management as it continues to consolidate. What are some of the key acquisitions and strategies you’ve witnessed within and think should be on our radar?

Let us know.

Cheers,
Yusuf Latief
Content Producer
Smart Energy International

Follow me on Linkedin

The package, originally secured to finance the construction and operation of TagEnergy’s Lakeside BESS project in October 2023, included an uncommitted accordion facility, enabling TagEnergy to incorporate Pitkevy into the funding structure.

The UK battery project also marks TagEnergy’s first split-contract project, with Tesla providing a Megapack 2XL battery system, and contractor RJ McLeod executing the site works and installation of the battery containers.

Flexitricity partners as route to market and battery optimiser, while independent renewable energy company RES has been appointed as asset manager.

Franck Woitiez, chief executive officer of TagEnergy said in a release: “We are proud to leverage this landmark debt package – secured without a revenue floor under our innovative financing model – to bring another facility to life as we work to add stability to the grid and accelerate the energy transition towards net zero.”

“Equally, we are pleased to be working with our trusted group of partners, from funding through to operations, to deliver the Pitkevy facility that takes TagEnergy’s secured portfolio to 320MW as we expand our footprint in the UK for the benefit of people and the planet.”

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EV-based BESS to balance Finnish and Norse demand

Andy Lowe, CEO at Flexitricity, added: “TagEnergy is driving change in the clean energy sector and we are delighted to now contract with them, having been working in partnership for a number of years.

“BESS projects like Pitkevy have a vital role to play in the UK energy transition and we’re confident that our advanced machine learning expertise and trading capabilities will deliver market-leading value.”

Construction has commenced and the energy park is scheduled to be operational at the end of 2024.

Financing breakdown

The project was financed under a non-recourse green loan package of up to £70 million ($88.2 million), provided by lenders Santander UK, Rabobank, and Triple Point on a fully merchant basis, except for Capacity Market revenues.

As for the Lakeside facility, the debt was arranged by IDCM as financial advisor, with TLT serving as borrower legal advisor, Burges Salmon as lender legal advisor, Aurora Energy Research as energy analytics provider, Everoze as technical advisor, WTW as insurance advisor, Ester as hedge advisor and RSM as the model auditor.

Jan Libicek, investment director at Triple Point, said: “We are thrilled to strengthen our partnership with TagEnergy and contribute to the expansion of the BESS sector in the UK.

“Our commitment to funding new BESS developments stands at the forefront of our strategy to foster a decarbonised energy grid. This collaboration highlights our mutual dedication to advancing the UK’s journey towards a cleaner, sustainable, and more resilient energy future.”

TagEnergy acquired its 100% stake in the battery storage facility from Intelligent Land Investments Group Plc in October 2022.

Expected to be complete in 2026, the project will see the facility expand to over 15,000 square meters. Combined with process enhancements, the upgraded facility is geared towards optimising operational performance and boosting manufacturing capacity to address growing demand.

Operational since 1906, the facility in Bad Honnef is one of the Swiss energy tech major’s key manufacturing locations in Europe, producing large power transformers, which form critical components of the electrical grid used to step up or down the voltage level for efficient transmission and distribution.

Over the years, the factory in Bad Honnef has delivered transformers to many of the leading TSOs, utilities and industries in Europe, such as those included in the strategic partnership with TenneT.

“Electricity will be the backbone of our entire energy system. In the global power system of 2050, we need around four times the power generation capacity and transfer of up to three times as much electrical energy compared to 2020”, said Bruno Melles, business unit transformers managing director at Hitachi Energy.

“The Bad Honnef facility is one example of our commitment to expand our global footprint and capacity at speed to meet accelerating demand driven by the energy transition.”

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Power transformer demand

The facility’s upgrade is expected to generate up to 100 new jobs in the region and address the rising demand for transformers for Europe’s power system stemming from increasing levels of renewable energy and electrification.

Additionally, according to Wood Mackenzie authors, demand for transformers has been increasing due to their high lead times and supply chain constraints.

According to the research and consultancy group, power transformer lead times have been increasing for the last two years – from 115 weeks in 2021, to 130 weeks on average in 2023.

Large transformers, they state, both substation power and generator step-up (GSU) transformers, have lead times ranging from 80 to 210 weeks, and some manufacturers, such as Hitachi Energy, have announced plans to expand capacity to meet this growing demand.

According to Hitachi, Energy, the factory’s expansion also reflects a wider scaling up of the company’s capacity in Europe.

In 2023, the company expanded production in Sweden with an additional 2,000 new jobs over the next two years, in addition to the acquisition of power electronics companies eks Energy and COET.

The roadmap is built around two pillars that are considered key, i.e. developing a power system fit for a carbon-neutral Europe while at the same time managing a secure and efficient power system for the region.

Or put another way this corresponds to ‘preparing the future’ while ‘managing the present’, to which the TSOs commit, stating: “This will require the continuous deployment of operational excellence, implementing efficient and operational market mechanisms, increasing regional coordination, and making the best use of information and communication technologies.”

Developing the power system

Starting with the power system for a carbon-neutral Europe pillar, the roadmap identifies five main areas where change is necessary to deliver on that.

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● Energy system flexibility: An accurate assessment of flexibility needs and potential is needed at national and European levels, as is a comprehensive ‘system of systems’ approach involving TSOs, DSOs and other sectors such as hydrogen to coordinate the deployment and use of the most efficient flexibility resources.

● Operating future grids: In a ‘system of systems’ approach, new approaches are needed, including enhanced real-time grid visibility, forecasting capabilities and controllability. Automation and AI will support operators in handling grid complexity while the electrification of end uses and sector coupling will require new risk-based methodologies, cybersecurity and new concepts for the coordination of operators.

● Infrastructure and investments: To accelerate the delivery of grid infrastructure both onshore and offshore coordinated planning will be required across the ‘system of systems’, as will massive investments in the transmission networks. Other requirements include reforming regulatory frameworks, ensuring fit-for-purpose financing mechanisms, developing seamless supply chains to overcome bottlenecks and enhancing engagement with local communities.

● Market design: Electricity markets will need to evolve, with strong long-term signals to enable investments in renewables, flexibility and grids, short-term markets to encourage efficient resource use and carbon-neutral flexibility and with incentives aligned with system capabilities and security, while other important aspects are transparency tools for a carbon-neutral system and potential changes to transmission tariff principles.

● Innovation development and uptake: While the TSOs are making breakthroughs in new strategic technologies by implementing ENTSO-E’s RD&I roadmap and the deployment of solutions, new measures regarding the adaptation of regulatory frameworks, the de-risking of first-of-a-kind projects, demonstrators and corresponding stakeholder engagement should be pursued.

Managing the power system

In the secure and efficient power system pillar, four main areas are identified in which the TSOs, with support and coordination by ENTSO-E, are playing multiple roles.

● Operational excellence, with support to TSOs to deliver efficient, resilient and secure system operation.

● Market development and operation, with the implementation of market mechanisms to efficiently operate the system and optimise social welfare for consumers.

● Regional coordination of national and regional actors.

● Information and communication technology, with support for the design and development of the ICT tools to manage the power system.

The roadmap document concludes that while planning and delivering the future power system, Europe needs to continue to rely on a strong, secure and efficient electricity supply.

“To ensure the balance between these two dimensions, ENTSO-E will need to manage intertwined and sometimes challenging approaches or activities while fulfilling these dual strategic goals. The strategic roadmap will focus its activities, resources and the stakeholder engagement of ENTSO-E on [these] twofold objectives.”

V2G systems have until recently been a technology in need of depth and exploration before fully coming onto the market as a widespread source of consumption management.

The systems involve electric-powered vehicles communicating with the power grid to sell demand response services, usually overseen by a third party, such as energy retailers or aggregators.

With increasing demand on the grid stemming from sources of variable renewable energy, it would be no exaggeration to call V2G a crucial component of the global energy transition.

According to IndustryARC, an analytics and consulting company, the global V2G market size is forecast to reach $28.12 billion by 2026, growing at a compound annual growth rate (CAGR) of 4.28% from 2021 to 2026.

Additionally, bidirectional charging – when electricity flows from the EV battery to the grid and then back to the vehicle – is a core component of this system and was analysed by ARC to grow at the fastest CAGR of 5.12% among the entire segment of charging types for electric vehicles over the forecast period.

Development of the tech surged in 2023, although companies seeking to invest in the market should still be selective about where they choose to do business.

According to AFRY Management Consultants Steffen Schaefer and Xavier Sichert in Market attractiveness for Vehicle to Grid, the ideal market for V2G would be one with a high share of intermittent renewable energy sources, a low share of interconnections with other countries and a high penetration of smart metering in private households and at corporate buildings.

In the meantime, as the market continues to develop, tech companies, automotive majors and utilities have been making moves.

This is what has caught our eye.

Octopus Energy launches first V2G tariff in the UK

Octopus Energy, the UK’s energy wunderkind, has launched the UK’s first mass-market V2G tariff, called Octopus Power Pack. The tariff uses V2G technology and Octopus Energy’s tech platform Kraken to balance charging and discharging when it’s best for the grid.

According to the company, the tariff works as a bolt-on that separates charging from the rest of the home and runs alongside each customer’s regular import tariff. Customers can also stack the benefits of payments for solar generation on top of this.

For eligibility, drivers need to stay below the usage limit of 333kWh per month and plug in their electric car for 170+ hours monthly (roughly six hours daily) to receive free charging. The rest of the process is automated.

Calculated under the assumption of 10,000 miles (16,093.44km) driven each year, the British energy giant claims that an average electric car driver will be able to save more than £850 ($1,070) a year in charging costs on the Power Pack, compared to charging on a standard variable tariff.

Octopus Power Pack is available to drivers with V2G-compatible electric cars, chargers and a smart meter available in the UK. Although there is currently only a limited number of car models that have this capability, car manufacturers such as Volvo, states Octopus Energy, have made commitments to release V2G-ready models soon.

The tariff also follows Octopus’ recent announcement of passing 200,000 customers signed up to its EV-optimised tariffs – Intelligent Octopus Go and Octopus Go – making up roughly a fifth of electric car drivers on UK roads.

The company clearly sees where the V2G segment is going and is preparing to be a key player.

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China’s Reform Commission sets out V2G planning recommendations

V2G revenues

In the US, Nuvve Holding Corp. reported recurring revenues from its proprietary V2G services.

The tech company’s intelligent, cloud-based software, Nuvve GIVe, is a platform that transforms electric fleets into mobile storage resources, providing electric grid resilience while also generating recurring revenues to offset fleet operation costs.

In essence, multiple EVs would provide enough “smart load” energy to sell back to the market, providing a revenue stream and lowering the cost of owning the EV in the first place.

In its Q3 financial results, announced December 2023, the company’s CEO, Gregory Poilasne, said the company is on pace to increase its revenues by more than 50%, resulting from orders, sales and deployments of charging stations connected to the GIVe V2G software platform.

Additionally, in January, Nuvve announced a $16 million project win with Fresno Economic Opportunities Commission’s (EOC’s) 50-shuttle fleet, to electrify the fleet and implement its Nuvve GIVe software.

Nuvve assisted Fresno EOC, which is one of the largest nonprofit community action agencies in the US, in securing grant funding through the Carl Moyer Memorial Air Quality Standards Attainment Program and Pacific Gas & Electric.

OEMs & V2G

Tech companies, however, are not the only ones with claims to stake in the market. EV original equipment manufacturers (OEMs), for example, are arguably the most poised for market penetration as they are in the starting position of the race – they manufacture EVs, which are the backbone of the system.

Two weeks following Nuvve’s project win with EOC, Nissan announced the launch of a new service – Nissan Energy Share – in Japan, coming March 1, 2024.

The new service features Nissan-unique energy management technology that controls the charging and discharging of EV batteries.

The service comes after conclusion of the Japanese auto major’s research into the most efficient ways of managing energy through EVs. Specifically, Nissa conducted different studies and field tests in locations such as Fukushima, validating its proprietary technologies for autonomously charging and discharging EV batteries.

Offered primarily to companies, businesses and municipal governments, Nissan said that the service is designed to enable optimal energy management in line with the needs and circumstances of customers; a ‘one-stop service experience’, from planning and system build-out to maintenance operations.

In addition to the system itself, the auto major says users will be able to apply for different subsidies, although details have not yet been released.

Also of interest:
Power sector measures key for smart charging in emerging economies states IEA
Sweden’s Polestar launches vehicle to grid and virtual power plant projects

Time pressure

Although tech and automotive companies are making moves in the right direction, there is a palpable time pressure that we also need to be cognizant of.

The market is clear, but the problem of managing increased loads from soaring rates of renewables coming online and EVs coming onto the road will not be going away anytime soon.

In the Netherlands for example, the problem of renewable energy causing grid lock has given grid operators headaches for years already, causing them to increasingly turn to flexibility as a solution.

The compact country is expected to have over 10 million battery-electric cars on the road by 2044; but with a grid at capacity, managing this demand will continue to be a pain point, perhaps mediated by V2G.

Add to this the upcoming deadlines for bans on internal combustion engines (ICEs) – both Europe and the UK angling for 2030 – and the weight of this demand only increases.

Surely then, it only makes sense that we tap more into the market, which provides lucrative opportunities alongside a clear route to managing these critical demand spikes.

The pressure to rev up the V2G market has been gaining urgency and clearly top industry players are responding. But what do you think? Who do you see as leading the market and what more is needed, whether from policy or from technology, to propel the market forward?

Let me know.

Cheers,
Yusuf Latief
Content Producer
Smart Energy International

Follow me on Linkedin

The 21 projects follow the prior financing of 28 projects by the country’s energy ministry amounting to €593 million ($637 million), also aimed at expanding and modernising the electricity distribution network throughout Romania.

According to Romania’s minister of energy, Sebastian Burdujam, the contract financing will be essential for Romania’s energy transition.

Commented Burdujam in a release: “The Modernization Fund is one of the greatest opportunities for development that Romania has in recent history, and our commitment is to make the most of it in the shortest possible time.

“What do these grant investments mean? Modernising electricity distribution networks and increasing their degree of resilience in the context of climate change, by moving overhead power lines underground; increasing the absorption capacity of new prosumers and renewable energy production capacities, a phenomenon we fully support; digitisation of networks through the introduction of smart meters, with a focus on large urban communities.”

Burdujam adds that, through the investments, the country will be transitioning its national energy model into “A system in 3D: decarbonised, digitalised, decentralised.”

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The financing includes:

• €268 million ($288 million) to Distribuție Energie Electrică SA, including
  • €8.8 million ($9.5 million) for modernisation of electric energy distribution networks project in Rășinari commune, Sibiu county.
  • €47.6 million ($51.2 million) for a project to increase the degree of safety of the Sibiu Nord 110/20kV transformer station and to close the 110kV loop between the Sibiu Sud – Cisnădie – Dumbrava stations, Sibiu county
  • €25.1 million ($27 million) for the 110kV RED Modernisation project in the Smardan-Barbosi-Filesti-Arcelor Mittal area and modernisation and integration into the SCADA of the 110/20/6kV Filești substation, Galați county
  • €161 million ($173 million) for a project to implement intelligent electricity measurement systems at the level of the county seat cities; €56.9 million in the North Transylvania area, €55.1 million in the South Transylvania area and €48.9 million in the North Muntenia area
  • €23.4 million ($25.1 million) for project – Transition to 20kV Moreni municipality and modernization of the 110/20/10kV Moreni electrical transformation station, Dâmbovița county

• €187 million ($201 million) to Delgaz Grid SA, including
  • €51 million ($54.8 million) for stage one of the modernisation and SCADA integration project of transformer stations
  • €34.7 million ($37.3 million) for stage two of the modernisation and SCADA integration project of transformer stations
  • €66.6 million ($71.6 million) for stage one of the modernisation, rehabilitation and voltage level improvement project in the low-voltage networks
  • €16.6 million ($17.8 million) for the Project of Common Interest, CARMEN (Carpathian Modernization of Energy Network) Volume 1, including the modernisation of LEA 110kV Şișcani – Glăvănești – Bârlad

• €59.8 million ($64.3 million) to Distributie Energie Oltenia SA, including
  • €15.6 million ($16.8 million) for modernisation of the 110/20/10kV Dăbuleni transformer station, Dăbuleni city, Dolj county
  • €14.3 million ($15.4 million) for modernisation and SCADA integration of the 110/20 kV Dragășani transformer station, Dragășani locality, Vâlcea county
  • €11.6 million ($12.5 million) for extension of low-voltage electrical distribution networks in the communes of Șimian and Obârșia Cloșani and increasing energy efficiency and increasing the quality of energy distributed to customers by modernising transformer stations, low-voltage network and branches related to the commune of Șimian, Mehedinți county

• €43.4 million ($46.6 million) to Rețele Electrice Dobrogea SA, including
  • €10.8 million ($11.6 million) to increase security of supply in Manasia, Ialomiţa
  • €32.6 million ($35 million) to modernise the distribution network in the towns of Frumusani, Vasilati, Galbinasi, Plataresti and Fundeni, Jud. Calarasi

• €39.8 million ($42.8 million) to Rețele Electrice Muntenia SA to increase safety in the electricity supply of the town of Balotești, by modernising the MV LEA 20KV lines Balotești, Radio Săftica, Săftica, Măgura, Ghermănești, Muntenia 1, Muntenia 2, Ana Aslan

• €29.3 million ($31.5 million) to Rețele Electrice Banat SA, including
  • €17.7 million ($19 million) for 20kV Avicola Berzovia LEA modernisation works through the partial transition from LEA to LES of the MV network, the transformation of overhead PTs into concrete-encased PTs and the modernisation of the low voltage LEA network in the towns of Duleu, Remetea Pogăniș, Valea Mare, Bocșa – Binisului street
  • €11.6 million ($12.5 million) for modernisation of the distribution networks in the City of Geoagiu, Geoagiu Bai and the localities: Aurel Vlaicu, Bozes, Cigmau, Homorod, Mermezeu-Valeni, Renghet, Poienari and Valeni

• €20.7 million ($22.2 million) to E-Distribuție Banat SA for modernisation of electrical networks in the Arad Nou project

• €18.4 million ($19.8 million) to Distributie Energie Oltenia SA, for modernization and introduction into SCADA of the 110/20kV Rogojelu transformation station, Rovinari city, Gorj county

The Modernisation Fund is a programme from the European Union to support 13 Member States to meet energy targets by helping to modernise energy systems and improve energy efficiency.

States included in the Modernisation Fund include Romania, Bulgaria, Croatia, Czech Republic, Estonia, Greece, Hungary, Latvia, Lithuania, Poland, Portugal, Slovakia and Slovenia.

The Tyrrhenian Link, a 970km, 1,000MW double submarine cable, is a new electricity corridor at the centre of the Mediterranean connecting the Italian mainland with Sicily and Sardinia.

This final financing sees €500 million ($540 million) signed in addition to the €1.4 billion ($1.5 billion) previously disbursed via loans signed in November 2022 and March 2023.

The final tranche will support the construction and commissioning of the link’s East and West sections.

The loan aims to foster the development of renewable energy sources and grid reliability and promote energy security through the interconnector.

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Tyrrhenian Link

In Sicily, Sardinia, and especially Campania, states Terna, there is increasingly strong production from non-programmable renewable sources such as solar and wind. The Tyrrhenian Link will increase electricity exchange capacity and thus support the development and better use of renewable energy flows.

Additionally, the project is anticipated to significantly improve grid reliability while increasing the competitiveness of producers in the electricity market.

The overall project involves two sections: East from Sicily to Campania and West from Sicily to Sardinia.

The East section is 490km long and connects the Fiumetorto landing point, in the municipality of Termini Imerese in Sicily, with the landing point in Torre Tuscia Magazzeno, near Battipaglia in Campania.

The West section is approximately 480km long and connects the Fiumetorto landing point to the one in Terra Mala, in Sardinia.

With terms of around 22 years from each drawdown, the loans have a longer maturity and more competitive costs than those generally available on the market. According to the TSO, this puts them in alignment with Terna’s policy to optimise its financial structure.

This operation brings total EIB financing for Terna to around €3.8 billion ($4.1 billion).

Around 50% of the project cost will be financed by the EIB.

The Tyrrhenian Link is expected to be fully operational in 2028 with some 250 companies involved in its implementation.

The Department has issued a Request for Proposals (RFP) for the second round of the Transmission Facilitation Program, a revolving fund supported by the Bipartisan Infrastructure Law to help overcome financial hurdles facing large-scale new and upgraded transmission lines.

Through the RFP, $1.2 billion in federal support is expected to accelerate transmission buildout through capacity contracts, an approach aiming to increase the confidence of investors and potential customers while reducing risk for projects.

Additionally, these federal investments are expected to unlock billions of dollars of state and private sector capital to build transformative projects that modernise and increase the reliability of the power grid.

“There’s no way around it: to realize the full benefit of the nation’s goal of 100% clean electricity by 2035, we need to more than double our grid capacity,” said US Secretary of Energy Jennifer M. Granholm.

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Transmission buildout and capacity contracts

Administered by the Grid Deployment Office, the Transmission Facilitation Program authorizes the country’s DOE to borrow up to $2.5 billion to assist in the construction of transmission lines that otherwise would not be built and encourage increased capacity of planned lines.

To drive home this construction, the DOE’s RFP will use a mechanism known as capacity contracts, which will commit the Department to purchase up to 50% of the maximum capacity of a transmission line.

Transmission infrastructure financing relies on demonstrating to potential investors that the line has committed customers. But customers often can’t commit until they are sure a project will be developed and available when needed.

This would be where the DOE’s capacity contract comes in, establishing the agency as an ‘anchor customer’ who can provide certainty for potential financers and other customers.

By offering capacity contracts to late-stage and ‘shovel ready’ projects, the DOE is hoping that investor and potential customer confidence will increase risk of project developers under-building or under-sizing transmission capacity contracts will decrease.

The DOE will sell its capacity rights in these projects to other customers to recover its costs.

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Solicitation round two

The RFP builds on the first solicitation issued by the DOE in 2022; on October 20, 2023, the department announced it entered into the first round of capacity contract negotiations for up to a total of $1.3 billion.

The negotiations resulted in the buildout for three transmission lines crossing six states that will add 3.5GW of additional grid capacity throughout the United States, equivalent to powering approximately 3 million homes.

The selected projects include the Cross-Tie 500kV Transmission Line (Nevada, Utah), Southline Transmission Project (Arizona, New Mexico), and Twin States Clean Energy Link (New Hampshire, Vermont).

DOE’s National Transmission Needs Study, released October 2023, estimates that by 2035 the United States must more than double existing regional transmission capacity and expand existing interregional transmission capacity by more than fivefold.

The submission deadline for Part 1 of the application is March 11, 2024.

Soon, DOE’s Grid Deployment Office expects to release a separate RFP focused on public-private partnerships to build transmission infrastructure that connects isolated microgrids to the grid in Alaska, Hawaii, and US territories.

Also on the radar are virtual power plant (VPP) provider Swell Energy’s acquisition of Renu Energy in Carolina, US, and Second Foundation’s acquisition of a Nano Energies brand in the Czech Republic.

Siemens Energy’s strong Q1

Revenue came in at €7.6 billion ($8.2 billion) reflecting a 12.6% increase, four months after the energy major reported a $5 billion loss and safety net from the German federal government.

In a release, the company said that, while all segments contributed to growth, the increase was particularly strong at Grid Technologies.

Exceptionally high orders exceeded an already outstanding level in prior year’s quarter, mainly driven by Grid Technologies’ product business and high-voltage direct current transmission system orders in Germany.

The company is further planning to achieve comparable revenue growth of 18% to 22% within the grid portfolio.

“The solid first quarter is encouraging, in part also due to project shifts, which are normal in plant engineering, especially with the market dynamics we are currently seeing,” said Siemens Energy CEO Christian Bruch in a release.

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Swell Energy acquires Renu Energy Solutions

Swell Energy Inc., an energy management and grid solutions provider, has acquired Renu Energy Solutions, a Carolinas-based company that offers customised residential and commercial solar and energy storage solutions.

The combination brings together a complementary set of operational and technological capabilities as well as a bi-coastal presence to enable the deployment of VPPs in key energy markets.

With the combination of Renu’s seasoned project development capabilities and Swell’s financing and VPP technology platform, the combined company says it is now well positioned to expand its footprint across the Southeast and mid-Atlantic market, and contribute to the strong growth in residential and commercial solar and storage capacity in the region.

Since 2010, Renu has offered residential and commercial energy solutions with an emphasis on installations and energy monitoring services. The acquisition includes Renu’s solar and storage maintenance subsidiary, Sun Service Specialists, which serves both Renu and non-Renu customers with thousands of distributed energy resources (DERs) across the East Coast.

Also of interest:
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How AI and advanced analytics will be key for the grid of tomorrow

With Renu serving as a regional hub, Swell’s channel partner programme provides other residential and commercial solar companies access to customer acquisition resources, fluid supply chain, critical software tools, financial products, grid services offerings and the opportunity to become VPP co-developers alongside Swell.

“With rapidly growing energy demand, favourable policies, and high solar potential, the Southeast is quickly becoming one the most attractive markets in the country for solar and energy storage systems,” said Jay Radcliffe, President of Renu.

“Swell’s robust technology portfolio combined with Renu’s full-service in-house team and unique expertise will drive innovation and ensure clean energy solutions are not only accessible but also efficient, reliable and tailored to the individual needs of our customers.”

Second Foundation acquires DES Holding

Czech-based technology group Second Foundation has signed an agreement on the acquisition of DES Holding, a flexibility aggregator and member of the Nano Energies group.

The agreement was signed on behalf of Nano Energies by its owner Petr Zahradník. The transaction marks the next step in Second Foundation’s strategy to gradually shift from focusing purely on financial algorithmic trading towards reaping the benefits of energy flexibility and smart management in renewable and other sources of energy.

Under the new owner, DES Holding will continue to use the Nano Energies brand with which its customers and partners are familiar.

The transaction does not involve the Nano Green division, an energy supplier active in managing power generation and consumption in smart households. Rather, Nano Green will be acquired by current managers David Brožík, Jan Hicl and Lukáš Beneš, the owners of the S9Y software studio.

The three managers have been at the helm of Nano Green for the past year and a half and will acquire Petr Zahradník’s shareholding to become the sole owners of Nano Green.

“In early 2024, we plan to launch a new service for our customers. It will enable fully automatic management of electricity generation and consumption. By offering the service, we will open the door for owners of smart homes and small businesses to participate in balancing the grid. In other words, they will be able to earn money by shifting their power production and consumption across time segments,” said Jan Hicl, chief product officer at Nano Green, in a release, unveiling the company’s plans.

The acquisition by Second Foundation is already the second such transaction involving subsidiaries of the Nano Energies group. Second Foundation acquired Nano Energies Trade in early 2022.

The transaction is still to be approved by the Czech Office for the Protection of Competition (ÚOHS). It is expected that the transaction will be closed in the first quarter of 2024.

For the latest finance and investment news coming from the energy sector, make sure to follow Smart Energy Finances Weekly.

I will also be attending Distributech International in Orlando Florida later this month. Will I see you there?

Cheers,
Yusuf Latief
Content Producer
Smart Energy International

Follow me on LinkedIn

To fully utilise all the potential that VPPs can offer in the next few years, we’ll need a major strategy overhaul. While COP28 agreements to transition away from harmful fossil fuels and triple our collective renewable energy production by 2030 are noble, it will take intentional and strategic goalposts to help us get there.

To reach the targets set forth at COP28, we must accelerate global energy capacity and make progress as soon as this year in order to more than double our renewable capacity by the end of this decade. But here’s the good news: VPPs are one of the most effective—and as yet, largely untapped—tools that we can use on this journey.

In 2024, progress for VPPs will mean stakeholders taking initial steps towards promoting VPP adoption by both Programme teams and Energy Procurement teams, fostering customer engagement, developing supportive policies and regulations, and leaning into open standards.

Down the line, I see an increased adoption of devices and smarter homes, leading to a smarter grid, smarter cities, and ultimately smarter communities.

Making 2024 count – First steps

Climate conversations are now mainstream. With this increased attention to the energy transition, regulators and lawmakers will continue to push utilities to take faster action.

Announcements like Michigan’s targeting of 100% clean energy by 2040, while critical, are just part of what is needed for true progress.

We need each utility and load-serving entity to participate more fully in the energy transformation. This will require engaged, progressive utilities to see the potential behind flexible energy technologies like VPPs that bring reliability, cost savings, and increased integration of renewable distributed energy sources.

This shift can promote a solid foundation for meaningful participation in the evolution of the energy landscape more broadly. 

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Incentivising community engagement 

Propelling utilities to increase VPP adoption also requires bringing customers along on the journey. Promoting this engagement requires education, so we need to focus on helping individuals understand the direct impact of their actions.

Regulatory bodies like rate makers are working to communicate these differences effectively. Major players such as original equipment manufacturers (OEMs) are also engaging with users in a meaningful and contextualised way, contributing to the development of an ongoing educational journey. Especially noteworthy is the shift towards more personalised incentives that resonate with customers. These incentives are designed to speak the customer’s language and address concerns that are genuinely meaningful to them.

Importantly, customers receive immediate value through their participation in VPP programmes. Benefits are both fiscal and societal, as participating customers can gain financial incentives through VPP solutions by sharing assets with the grid or reducing their usage. This not only provides communities with financial benefits but also aids utilities in effectively handling our growing electrical demands. 

As VPPs are more widely adopted, the frequency and duration of their dispatch will increase with only minor added costs for operators and utilities.

The grid is constantly balancing many things, be it frequency capacity, energy demands, or emergency events. Those value streams create a direct benefit to utilities by better balancing their cash flow and providing ratepayers with greater returns. This is also the best cost option for utilities since the cost of incentives is lower than non-VPP alternatives to meet energy strain.

The equation is simple: To meet demand, utilities can either build and turn on more peaker plants, or they can pour those same dollars through VPPs into the hands of communities and customers.

Open standards are not optional

Beyond customer engagement, the industry also needs standardisation of protocols. This involves creating streamlined communication threads, allowing devices to seamlessly interact with each other and connect with grids through a software middle layer.

Simplifying these interactions reduces friction in our infrastructure, leading to accelerated device adoption, improved affordability and streamlined execution of programmes like virtual power plants.

This approach will also lead to the enhancement of products and services in the energy sector. Although work is already underway on these protocols, their widespread implementation is vital for enhancing the overall efficiency of the industry’s energy transition.

Interoperability and open standards are essential for multi-asset, multi-vendor VPPs—and are critical for scaling VPP adoption. While lack of standardisation presents challenges, companies are navigating these obstacles.

Despite hurdles, companies like AutoGrid work to promote VPP adoption, accelerate the energy transition, and improve widespread access to sustainable energy. I see even more consolidation happening in this space, leading more technologies and players to simplify steps for users.

For example, Uplight’s recent acquisition of AutoGrid will help expand the existing ecosystem of participating devices, along with other benefits.

Net zero within reach

As I think about how we’ll reach 2030 net zero goals, embracing VPPs is essential. From my experience spanning the energy sector, I know it may be hard, but we can do hard things.

It will just take the right partners, incentive structures, engaged customers and cutting-edge technologies. With these goalposts as our blueprint, we can work to unlock the full potential of VPPs for 2024 and beyond. It’s only then that we can take those lofty goals set forth during COP28 and make them achievable.

About the Author

As Autogrid’s VP of VPPs, Gisela Glandt leads AutoGrid’s Virtual Power Plants business and oversees the growth and health of Autogrid’s Distributed Energy Partner ecosystem. Prior to AutoGrid, Gisela led Nest’s Smart Home and Energy Partnerships at Google, with a focus on formulating and executing growth strategies for cutting-edge products and cultivating strategic partnerships.

The decision is an essential regulatory step enabling Hawaiian Electric to move forward with $95 million in funding granted under the federal Infrastructure Investment and Jobs Act (IIJA) by matching it with $95 million to come from customers.

The programme includes:

• Wildfire Mitigation – System hardening and increased situational awareness and control (e.g., cameras, sensors and reclosers) in areas identified as having elevated wildfire risk.
• Hazard Tree Removal – The removal, not trimming, of large off-right-of-way trees that are weak, dead, diseased, or structurally compromised and pose a risk to falling on power lines.
• Critical Transmission Hardening – Replacing poles and conductors on high-priority transmission lines, including two on Maui.
• Critical Circuit Hardening – Strengthening circuits serving critical customers such as hospitals, public infrastructure and critical defense facilities.
• Critical Pole Hardening and Replacement – e.g., Poles that support multiple circuits; replacing poles with fire-resistant materials.
• Undergrounding portions of certain distribution circuits.
• Control Center Resilience – Hardening of existing system control centers, relocating and elevating the Maui control center to avoid flooding and developing a backup control center on Oahu.

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“As climate change progresses, the frequency and severity of severe weather events is likely to increase,” the PUC stated in its decision (Docket 2022-0135).

“Given the critical services that rely on electric service to function and our state’s geographic isolation, it is imperative that our electric grid be able to withstand these growing challenges.”

Hawaiian Electric’s 5-year plan includes a slate of initial, foundational grid resilience investments, including the replacement and strengthening of 2,100 poles on critical circuits, as the first phase of a long-term climate adaptation effort.

The awarding of the federal grant was first announced by President Biden during a visit to Maui soon after the deadly August 8 wildfires that devastated Lahaina and caused widespread outages.

“We appreciate the PUC’s approval of our plan and we thank the US Department of Energy and the Biden Administration for their funding support as we work with partners across the state to help Maui recover, to reduce the risk of wildfires and to make our system stronger,” said Colton Ching, Hawaiian Electric senior vice president of planning and technology.

The deal, which sees the Group expand its geographical scope, forms part of its growth strategy focussed on that country as well as Europe as it seeks to become an international energy company.

So far as part of the closing $250 million has been drawn out of the $400 million, with Elia Group WindGrid subsidiary serving as the designated holding entity.

The proceeds are to be fully committed to fund project developments in electricity transmission and renewable energy generation.

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In particular, the group will offer its expertise and experience in the development, construction, operation and maintenance of offshore transmission infrastructure, HVDC technology, transmission planning and congestion management to the partnership.

On the initial announcement of the acquisition in December, Catherine Vandenborre, then interim CEO of Elia Group, said: “With our first investment, WindGrid stands ready to be a steadfast ally seeking to proactively establish offshore grid infrastructure and support renewable energy developers in search of secure connections to onshore electricity networks.

“By harnessing our extensive expertise and engaging in co-investment ventures on the global stage, WindGrid is committed to playing a pivotal role in expediting the energy transition.”

Elia states energyRe Giga to be an established partner with a strong pipeline of projects and with a unique focus on transmission-led generation combining high voltage direct current (HVDC) transmission with emissions-free energy sources.

These include a 50% stake in Clean Path New York, a future 280km HVDC transmission line and 3.8GW onshore generation in New York, and a 40% stake in SOO Green, a future 560km transmission line from the MISO to PJM.

The company also has a minority stake in the 2.4GW Leading Light Wind offshore wind development project in the New York Bight, which was contracted in January by the New Jersey Board of Public Utilities.

energyRe Giga’s assets are sold upon completion of each project, with the opportunity to reinvest the capital to support further portfolio expansion.